Process or delivery speed represented by the ratio of permeability and porosity is shown to provide a continuum between conventional, tight and shale gas reservoirs. The surprising result, based on core data from various North American basins, leads to distinctive flow units for each type of reservoir.

The approximate boundary between viscous and diffusion dominated flow is estimated with Knudsen number. Viscous flow is present, for example, when the architecture of the rock is dominated by megaports, macroports, mesoports and sometimes microports (port = pore throat). Diffusion flow on the other hand is observed at the nanoport level. Results from this research compare well with the observation that grains and pores are smaller in shales as compared with tight and conventional gas formations.

The process speed concept has been used successfully in conventional reservoirs for several decades. However, the concept presented in this paper for tight gas and shale gas reservoirs, with the support of core data, is new, and permits differentiating between viscous and diffusion dominated flow. This is valuable, for example, in those cases where the formation to be developed is composed of alternating stacked layers of tight sands and shales, or where there are lateral variations due to facies changes.

It is concluded that there is significant potential in the use of process speed as part of the flow unit characterization of unconventional gas reservoirs.

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